Natural gas, also known as methane, is a colorless, odorless, fuel that burns cleaner than many other traditional fossil fuels. As used herein, the term “gas” means and includes any gas, including natural gas. The term “diverted,” pump,” “pumped,” “pumping,” “compress,” “compressing,” “compressed,” and the like shall mean channeling, compressing, and diverting. As used herein, the term “line” or “lines” shall mean and include pipes, lines, channels, and the like. It is one of the most popular forms of energy today. It is used for heating, cooling, production of electricity and it finds many uses in industry. Increasingly, natural gas is being used in combination with other fuels to improve their environmental performance and decrease pollution.
Natural gas is most commonly produced by drilling into the Earth's crust. A well or borehole is drilled into pockets of natural gas that have been trapped below the surface of the Earth. The natural gas is then compressed or piped to the Earth's surface. Once the gas is brought to the surface, it is refined to remove impurities, like water, other gasses, and sand. Then it is transmitted through large pipelines that span the continent and the world. In fact, natural gas has become a very important commodity.
Natural gas is supplied by many producers and utilized by many users. Factories and electric power plants may get gas directly from the pipeline using arrangements made through a marketer, supplier or producer. Residential and smaller businesses generally buy gas from a local distribution company or utility. Just like any other commodity, natural gas must be produced, sold and shipped to its end users. However, unlike other commodities, natural gas cannot be stored by the customer or by the producer in a warehouse until it is utilized. Because of the difficulty of storage, contracts of various types between producers, users, and third parties may be utilized to allocate the duties and costs and risks in the event of disruptions in either the supply or the demand. Disruptions may occur on a very short term basis. Various arrangements between the producers and users such as fixed prices, indexed prices, caps, take or pay arrangements, and the like may be utilized. In any event, a disruption will mean that one party or another may lose money if either a producer's supply is interrupted and/or a user's demand is interrupted. Many reasons for short term disruptions exist and may include plant maintenance or breakdowns, gas well problems, pipeline problems in one section of the pipeline, and the like.
One means for limiting risk, or profiting from such disruptions in supply and demand, involves trading in various contracts, derivatives, futures, storage rights, and the like related to gas. Generally, even in the short term, many purchasers and suppliers are available for this purpose, and assuming a price can be agreed upon, the supply and demand caused by the various disruptions can be matched. Thus, even in the short term, the interruptions on the supplier end will often be substantially equal to the disruptions on the demand end. In this case the buy and sells of the various contracts in gas can be matched. If the supply is roughly equal to the demand, then the gas prices tend to remain more stable. On the other hand, if the supply is not equal to the in the short term demand, then short term price fluctuations, and losses to one party or another, can be quite high. Moreover, if a trader takes a short term position he will typically not know what disruptions, either in the supply or demand, may occur in the future. Thus, it would be highly advantageous to the trader to know with high certainty that the capability for either accepting or producing large quantities of gas is ultimately available to avoid the likelihood of large losses by being on the wrong side of a trade.
Prior art gas storage facilities do not provide the required capability for either accepting or producing large quantities of gas in the time frames required for short term trading. For instance, the turn around costs of storing gas and retrieving gas are typically quite high in prior art gas storage facilities. For instance, turn around costs of inserting gas into and out of prior art underground storage requires large expenditures of energy/money for compressing, heating, cooling, and the like effectively making many short term turnarounds financially unfeasible. Some types of reservoirs are structurally damaged if alternately increasing/decreasing pressure cycle changes occur too frequently. There is also the problem of changing the equipment configuration including valves, compressors, and the like, to permit changing the direction of flow of the gas supplies. As well, there is the significant problem of pressure surges and drops, pressure waves, and the like produced in the pipeline system as a result of changing flow direction that may cause damage throughout the system. The minimum time for changing the direction of flow of gas for prior art utilities is at least one to two days, although as discussed above, frequent changes in gas flow directions for prior art gas storage facilities is economically unfeasible due to high turnaround costs and/or unfeasible due to potential damage to the facilities, including damage to the underground storage reservoir itself. In any event, a turn around time of one to two days for changing the direction of flow of gas into or out of the storage is too slow for use in short term trading, even assuming the other problems discussed above could be overcome.
Because of its gaseous nature and volatility, one of the most economically viable manners of storing natural gas is in specialized underground warehouses called natural gas storage fields. These storage fields consist of underground caverns, hollowed out salt domes, depleted natural gas and oil fields, or in some cases water-filled domes.
Underground storage, in common usage, is gas transferred from the reservoir of discovery to other reservoirs, usually closer to market areas, where it is stored until needed to meet market demand. Natural gas is stored in underground reservoirs primarily to ensure the capability of the gas industry to meet seasonal fluctuations in demand. Underground storage supplements the industry's production and delivery systems, allowing supply reliability during periods of heavy gas demand by residential and commercial consumers for space heating. Prior art storage facilities have utilized high pressure storage of natural gas to meet these demands.
These storage facilities/fields act as a buffer between the pipeline and the distribution system of the natural gas. Storage allows distribution companies to serve their customers more reliably by withdrawing more gas from storage to meet customer demands during peak use periods. It also allows the sale of fixed quantities of natural gas on the spot market during off-peak periods. Having local storage of gas also reduces the time necessary for a delivery system to respond to increased gas demand. Storage also allows continuous service, even when production or pipeline transportation services are interrupted. However, the time required to withdraw gas and the time required to re-fill these storage facilities is a source of great time, expense and danger to suppliers, consumers and the like.
For example, there are well more than 400 underground storage sites in 27 states across the United States and Canada. Together, these sites can hold upwards of 3 quads of natural gas, ready to be withdrawn at any time. (A quad is an abbreviation for a quadrillion (1,000,000,000,000,000) Btu. For natural gas, roughly equivalent to one trillion (1,000,000,000,000) cubic feet, or 1 Tcf.) Despite these high numbers, storage capacity is always increasing in order to accommodate increased gas usage and improve reliability. However, the underground storage of today is drastically limited in its operational uses and abilities.
The three principal types of underground storage sites used in the United States today are: (1) depleted reservoirs in oil and/or gas fields, (2) aquifers, and (3) salt formations. Each type has its own physical characteristics (porosity, permeability, retention capability) and economics (site preparation costs, deliverability rates, cycling capability), which govern its suitability to particular applications. As used herein, the term gas storage facility means and refers to any of the three principal types of underground storage sites, i.e. depleted reservoirs, aquifers, and salt formations.
Most existing gas storage in the United States is held in depleted natural gas or oil fields located close to consumption centers. Conversion of a field from production to storage duty takes advantage of existing wells, gathering systems, and pipeline connections. The geology and producing characteristics of a depleted field are also well known. However, choices of storage field location and performance are limited by the inventory of depleted fields in any region.
The reservoir rock of an underground storage cavern in which natural gas is normally stored consists of porous sandstone and limestone. It is quite common that these formations can contain 30% or more pore space by volume. In common cases, the gas is pressurized and injected into the storage reservoir as desired. Further, as desired, the injected natural gas may be produced from the storage reservoir when needed. Accordingly, the art field is in search of a method of utilizing depleted field storage facilities to obtain an utmost benefit.
In some areas natural aquifers have been converted to gas storage reservoirs. An aquifer is suitable for gas storage if the water-bearing sedimentary rock formation is overlaid with an impermeable cap rock. While the geology of aquifers is similar to depleted production fields, their use in gas storage usually requires base (cushion) gas and greater monitoring of withdrawal and injection performance. Deliverability rates of aquifers have been enhanced by the presence of an active water drive. However, the use of aquifers as natural gas storage is, like depleted fields, limited by the presence of an aquifer. Accordingly, the art field is in search of a method of utilizing aquifer storage facilities to obtain an utmost benefit.
Salt formation storage facilities provide very high withdrawal and injection rates compared with their working gas capacity. Base gas requirements are relatively low. To date, the large majority of salt cavern storage facilities have been developed in salt dome formations located in the Gulf Coast States. Salt caverns leached from bedded salt formations in Northeastern, Midwestern, and Western States are also being developed to take advantage of the high volume and flexible operations possible with a cavern facility. Accordingly, the art field is in search of a method of utilizing salt formation storage facilities to obtain an utmost benefit.
Additionally, storage facilities are classified as seasonal supply reservoirs (depleted gas/oil fields and aquifers for the most part) and high-deliverability sites (mostly salt cavern reservoirs). Seasonal supply sites are designed to be filled during the 214-day nonheating season (April through October) and drawn down during the 151-day heating season (November through March). High-deliverability sites are situated to provide a rapid drawdown (or rebuilding) of inventory to respond to such needs as volatile peaking demands, emergency backup, and/or system load balancing. However, prior art high-deliverability sites are drawn down in 20 days and refilled in 40 days, a relatively large period of time. Accordingly, the art field is in search of a method of utilizing a high-deliverability natural gas storage facility that may be cycled in about ten days. In this context, a cycle is the process of taking the gas cavern from minimum fill to maximum fill and back to minimum fill.
High deliverability may be achieved in a depleted oil or gas reservoir if the reservoir rock has high porosity and permeability (allowing a rapid flow of gas), and the reservoir has sufficient base gas pressure and a sufficient number of wells to maximize withdrawal. Additionally, it would be desirable to be able to refill a reservoir in a reasonably short time. Accordingly, salt cavern storage is ideal for high deliverability, as the entire cavern is one large pore. On average, salt storage facilities can withdraw their gas in about 20 days versus 71 days for aquifers and 64 days for all depleted oil or gas reservoirs. However, the time needed for re-fill is nearly twice that of drawing the natural gas.
Underground storage in depleted gas/oil fields is used when gas can be injected into reservoirs with suitable pore space, permeability, and retention characteristics. All oil and gas reservoirs share similar characteristics in that they are composed of rock with enough porosity so that hydrocarbons can accumulate in the pores in the rock, and they have a less permeable layer of rock above the hydrocarbon-bearing stratum. The hydrocarbon accumulation in the porous rock is pressurized by the weight of hundreds or thousands of feet of rock on top of the reservoir. When a well hole penetrates the impermeable cap layer of rock, the hydrocarbon under pressure is exposed to the much lower atmospheric pressure, and gas can flow into and out of the well.
Depleted oil and gas reservoirs are the most commonly used underground storage sites because of their wide availability. The depleted reservoirs use the pressure of the stored gas and, in some cases, water infiltration pressure to drive withdrawal operations. Cycling is relatively low, and daily deliverability rates are dependent on the degree of rock porosity and permeability, although the facilities are usually designed for one injection and withdrawal cycle per year. Accordingly, the art field is in search of a method by which the cycling may be increased.
Daily deliverability rates from depleted fields vary widely because of differences in the surface facilities (such as compressors), base gas levels, and the fluid flow characteristics of each reservoir. Retention capability, which is the degree to which stored gas is held within the reservoir area, however, is highest of the three principal types of underground storage.
In order to use an abandoned gas reservoir for storage, one or more of the wells used for extraction are typically used to inject gas. As with extraction, the more porous the rock, the rate of injection may be greater. As pressure builds up in the reservoir, the rate of injection slows down (pushing the gas in against higher pressure requires more force). Similarly, when the reservoir is at peak pressure, the rate of extraction is greater than at minimum pressure. Accordingly, the art field is in search of a method that does not encounter the difficulties of slow fill and slow draw.
The factors that determine whether a gas reservoir will make a good storage reservoir are both geographic and geologic. The greater the porosity of the rock, the faster the rates of injection and withdrawal. In some cases, where the reservoir rock is tight or of low porosity, then some form of stimulation of the reservoir may also be performed. This would include various methods to introduce cracks into the reservoir rock, thus increasing the opportunities for the hydrocarbon to flow towards the well hole.
The size of the reservoir (the thickness of the gas-bearing rock stratum and the extent to which the stratum is covered by cap rock) is another factor. Location is also a factor. If the reservoir is not close to existing pipelines or market areas and distribution lines, then greater expense will be incurred to establish connecting pipelines and less utility maybe derived. Accordingly, the art filed is in search of a method that utilizes reservoirs to obtain an utmost performance.
An aquifer storage site is a water-only reservoir conditioned to hold natural gas. Such sites are commonly used as storage reservoirs only when depleted gas or oil reservoirs are not available. Aquifers have been developed exclusively in market areas. In general, aquifer storage is more expensive to develop and maintain than depleted gas or oil reservoir storage.
Aquifer storage deliverability during the heating season is designed around specific customer requirements. These requirements may be for deliveries over a set period of time, for instance, 20, 60, or 120 days. The overall facility design reflects these combined requirements. These requirements also delimit the degree of cycling, that is, the number of times total working levels may be depleted and replenished during a heating season that may occur at an aquifer site. The sustained delivery rate cannot exceed design limits. Otherwise, unlike depleted oil and gas reservoir storage where cushion gas can be tapped when needed, tapping cushion gas in an aquifer storage site can have an adverse effect upon reservoir performance. Accordingly, the art field is in search of a method of utilizing an aquifer to obtain an utmost benefit.
Salt formations have several properties that make them ideal for storing natural gas. A salt cavern is virtually impermeable to gas and once formed, a salt reservoir's walls have the structural strength of steel. Thus, gas cannot easily escape the large hollowed-out shape that forms a salt storage cavern.
There are two basic types of salt formations used to store natural domes and beds. Salt domes are very thick salt formations. A salt dome formation might be a mile in diameter, 30,000 feet in height, and begin about 1,500 feet below the surface. The depth of the caverns that are hollowed out within the formation is critical for reasons of pressure and structural integrity. The pressure at which the gas can be stored is a function of the depth of the cavern. However, at extreme depths, as temperature and pressure increases, salt behaves as a plastic and will creep or flow, which can become a major consideration in cavern construction possibly leading to cavern closure. Thus, salt storage is generally limited to depths shallower than 6,000 feet. Accordingly, the art field is in search of a method of utilizing a low depth salt cavern to obtain an utmost benefit.
A salt bed storage site, on the other hand, is generally developed from a much thinner salt formation (less than 1,000 feet) located at shallower depths. As a result, the height-to-width ratio of the leached cavern is much less than with dome reservoirs, which are relatively high and narrow. Salt bed storage formations also contain much higher amounts of insoluble particles (shale and anhydrite rock) than salt dome formations. These materials remain in the reservoir after the leaching process and affect the flow velocity and capacity of the reservoir itself. In addition, because the height/width aspect is thin, the flatter reservoir ceiling is subject to greater stress and potential wall deterioration. As a result of these as well as other factors, salt bed storage development and operation can be more expensive than that of salt dome storage.
The term salt formation, as used herein, refers to both salt bed and salt dome storage facilities.
A salt formation storage facility is prepared by injecting water (leaching) into a salt formation and shaping a cavern. The deliverability rates of a salt formation are high because a salt formation reservoir is essentially a high-pressure storage vessel (that is, an underground tank). Base gas requirements are low (25 to 40 percent). On average, salt formation storage is capable of multiple cycling of inventory per year, in comparison to the typical one cycle or less for depleted gas/oil field and aquifer storage. As such, salt formation storage is well suited for meeting large swings in demand. However, prior art methods of utilizing salt formations have required using compressors to compress natural gas to high pressure within the storage facility. As a result, often expensive and time consuming compression, heating/cooling and energy costs have been required to use the storage facilities. Accordingly, the art field is in search of a method of use of a salt storage facility that obtains a maximum benefit of the salt formation storage facility.
Further, a salt cavern site occupies a much smaller area than an oil or gas reservoir. On average, the amount of acreage taken up by a depleted gas/oil field reservoir is more than a hundred times the amount of acreage taken up by a salt dome. Consequently, a salt cavern storage operation is generally easier to monitor than a gas/oil field reservoir operation made up of many wells. Development time is also much less for salt formation storage than for gas/oil field reservoirs. On average, it takes about 18 to 24 months to develop a salt reservoir while a gas/oil field reservoir takes 24 to 36 months. Thus, a new salt formation storage site may begin to pay off sooner than a gas/oil field reservoir. Accordingly, the art field is in search of a method of use of a salt storage facility to assist in maximizing a pay off of the developmental costs.
For the same working gas capacity, new salt formation storage reservoirs are also capable of yielding much greater revenues for a heating season than conventional gas/oil field reservoirs. However, present methods of use for salt formations are limited to generally about one turnover per season. A generally large percentage of the salt storage facilities exist in the southern states of the U.S, but because of the many benefits of a salt formation, plans are underway in the Midwest and northeast to develop such salt storage facilities. These facilities would augment directly the operations of nearby gas distribution companies. Accordingly, the art field is in search of a method of utilizing such salt formations to obtain a maximum benefit of the salt storage facility.
A most important characteristic of an underground storage reservoir is its capability to hold natural gas for future delivery. The measure of this is called working gas capacity: the amount of natural gas inventory that can be withdrawn to serve customer needs. In addition to working (top storage) gas, underground storage reservoirs also contain base (cushion) gas and, in the case of depleted oil and/or gas field reservoirs, native gas. Native gas is the gas that remains after economic production ceases and before conversion to use as a storage site. Upon development of a storage site, additional gas is injected and combined with any existing native gas in order to develop and maintain adequate storage reservoir pressure to meet required service. The resulting (permanent) inventory is referred to as the base or cushion load. During heavy demand periods, some base gas may be withdrawn temporarily and delivered as working gas, but over the long term, base levels must be maintained to ensure operational capability.
Natural gas is one of the most plentiful natural resources in North America and the reserves of the U.S. and Canada are enough to supply this continent well into the next century. However, the need for natural gas storage and violent supply swings arises because the demand for natural gas during the winter months exceeds the nation's production capacity, particularly in the Upper Midwest and Northeast. The U.S. consumes considerably more gas than it can produce during winter months because the interstate pipelines which transport natural gas from producing gas and storage fields in the Gulf Coast and the nations production regions to the market regions of the U.S. often do not have the capacity to transport the amount of natural gas needed during the peak demand periods, resulting in localized shortages of natural gas in the upper Midwest and Northeast U.S. Accordingly, the art field is in search of a method of transporting and storing natural gas that allows for a greater flexibility during peak demand periods and peak over supply periods.
Additionally, when the pipelines are loaded to their maximum capacity a bottleneck is formed in these pipelines as it is impossible to get additional gas into the pipelines until some of the gas has been consumed along the way. After some of the gas has been consumed, pipeline capacity opens up again and more gas can be placed into the system. Natural gas storage fields located to the north or downstream of this bottleneck have here-to-for been the only solution to this problem. Accordingly, the art field is in search of a method of utilizing natural gas storage for overcoming the bottleneck problems currently experienced by end consumers, suppliers and others.
As is common with natural gas, periods throughout the year are varying in regards to usage. During certain periods of the year usage may be higher than other periods of the same year. However, a gas pipeline only has a maximum capacity. Once the maximum capacity is reached in the pipeline, no more gas may be added to the pipeline. To further complicate matters, gas supply sources are commonly concentrated only in certain portions of an area. For instance, gas supply is most common in the southern portion of the U.S. Accordingly, the natural gas must be transported to other portions of a country or region to be used.
A major problem encountered with natural gas pipelines is when demand exceeds the supply of the pipeline. During the winter months of a year, natural gas will be depleted from the pipeline at a rapid pace in the Northern portions of a country where winter months require heating. The suppliers of natural gas can attempt to produce more gas to fill the pipeline, but this requires more time and effort. The prior art has tried to solve this problem with supplies from the depleted fields, aquifers and salt formations into the pipeline, but often it is not enough and there are severe shortages and price swings of natural gas. Accordingly, the art field has sought a system and method of use to balance the periods of high use and high supply by having alternate sources from which to divert natural gas (diverting natural gas, as used herein, means either filling or removing natural gas from a natural gas storage facility).
Likewise, prior art high pressure storage facilities require compressors to force natural gas into the natural gas storage facilities, especially as the high pressure storage facilities become approach capacity. These compressors require tremendous amounts of energy, thereby raising the costs of storage. Likewise, when releasing the high pressure gas from the high pressure natural gas storage facilities, the gas must be decompressed as the flow enters the pipeline, thereby, again, raising the cost of the natural gas storage and retrieval operations. Therefore, the constant adjustment to the pressure of the gas both into and out of high pressure natural gas storage facilities decreases the flow of the natural gas. A decrease in flow both into and out of the natural gas pipeline makes it extremely difficult to make quick changes in the flow of natural gas in a gas pipeline. Changes would occur much more quickly if the flow rates both into and out of the natural gas storage facility were maintained high. Accordingly, the art field is in search of a method of utilizing natural gas storage facilities in a manner that responds quickly to a change.
One prior art solution is disclosed in U.S. Pat. No. 4,858,640 to Kauffman. This patent discloses a network to be supplied by coordinating removal of gas from the individual storage caverns at an originally high storage pressure to a minimum residual pressure which is still below the operating pressure in the consumer network. This patent uses a system of valves and compressors to store high pressure gas in storage caverns. This patent does not disclose a relatively shallow depth storage cavern that may be used at a storage cavern operating pressure that is nominally the pressure of a pipeline. Accordingly, the art field is in search of a method of use whereby a relatively shallow depth and low pressures gas storage facility may be used with an existing network.